Sources of fossil fuels useful for heating, transportation, and the production of chemicals as well as petrochemicals are becoming increasingly more scarce and more expensive. Industries such as those producing energy and petrochemicals are actively searching for cost-effective engineered-fuel alternatives for use in generating those products and many others. Additionally, due to the ever increasing costs of fossil fuels, transportation costs for moving fuels for production of energy and petrochemicals is rapidly escalating.
Energy and petrochemical producing industries, and others, have relied on the use of fossil fuels, such as coal, oil and natural gas, for use in combustion processes for the production of energy (heat and electricity). Combustion is a thermochemical processes that releases the energy stored within the fuel source. Combustion takes place in a reactor in the presence of air or oxygen. A boiler is a type of a reactor that is used for heating water to generate steam. Traditional power plants use a boiler to generated steam which is used to power turbines for producing electricity.
The nature of the combustion of fuel causes significant amounts of pollutants to be released from the fuel and transferred into the produced gas. The pollutants in the gas are released into the environment unless they are captured or treated. Fuels often contain multiple chemical elements in different proportions that could give rise to various environmental or technological problems during or after they are used as an energy source. Such chemical elements include sulfur, halogens (e.g., Cl, F), nitrogen, and trace heavy metals including mercury (Hg). As described herein, the higher content of sulfur, chlorine, or fluorine causes serious corrosion of system equipment and creates the hazardous air pollutants. Trace elements may also be a threat to the environment or to human health (e.g., Hg, Cd, Pb, As, Cr, Se), may cause additional corrosion problems (e.g., Na, K), or may pollute or poison any catalysts (mainly As) or sorbents (e.g., powdered activate carbon) or catalysts (e.g., SCR) used downstream. For example, the combustion of fossil fuels such as coal, oil and natural gas in an oxidizing atmosphere creates NOx, a precursor to ground level ozone which can trigger asthma attacks. Combustion of fossil fuels is also the largest single source of sulfur dioxide (SO2), which in turn produces very fine sulfates particulates. Fine particle pollution from U.S. power plants has been estimated to cut short the lives of over 30,000 people each year. Furthermore, hundreds of thousands of Americans suffer from asthma attacks, cardiac problems and upper and lower respiratory problems associated with fine particles from power plants. To avoid or minimize problems associated with these elements, and/or products formed from these elements that may be liberated or produced during or after the combustion processes, one or more suitable technologies are needed to reduce their emission and release into the environment.
Primary sources of SO2 emissions are industrial operations such as power plants (e.g., coal or oil fired). In the U.S., the emissions from these industrial operations must follow Environmental Protection Agency (“EPA”) regulations set by the 1990 Clean Air Act Amendment. As new coal burning power generation facilities are being constructed, there has been a renewed interest in economical methods of reducing SO2 emissions. (Wu, C., Khang, S.-J., Keener, T. C., and Lee, S.-K., Adv. Environ. Research, 8, 655-666, 2004). It is reported that more than 250 techniques for flue gas desulfurization (FGD) have been proposed or developed on a worldwide basis (Oxley, J. H., Rosenberg, H. S., Barrett, R. E., Energy Eng. 88, 6, 1991). However, relatively few of those processes are currently in use because of low efficiency (Makansi, J., Power, 137, 23-56, 1993).
Power plants are the largest source of airborne mercury emissions in the U.S. Eventually the mercury in the air passes into the water, where it is converted into methylmercury (CH3Hg+), and enters the food chain. Methylmercury is a neurotoxin which accumulates in the body and primarily results from consuming contaminated fish and seafood. Regulatory agencies like the Food and Drug Administration (FDA) have issued guidance to reduce exposure methylmercury by limiting consumption of certain types of fish, but prior to 2012, there have been no federal regulations curtailing the emissions of mercury and other toxic pollutants.
In response to growing concern about emissions from traditional, fossil fuel-burning power plants, the EPA has required that emissions of criteria pollutants, such as oxides of nitrogen and sulfur (NOx and SOx), and toxic pollutants like mercury (Hg), be drastically reduced. In response, power plants have begun expensive retrofitting operations in order to reduce these emissions. However, as discussed in greater detail below, these mitigation strategies have had their own unintended consequences and have led to the production and emission of additional pollutants, such as sulfur trioxide (SO3) and sulfuric acid (H2SO4).
In addition to fossil fuels, municipal solid waste (MSW) is source of fuel for combustion. Fuels derived from MSW with minimal processing to remove some of the metals are often called refuse-derived fuels (RDF), or in some cases called solid-recovered fuels (SRF). The drawbacks accompanying combustion of MSW include the drawbacks of combustions of fossil fuels as described above, including the production of pollutants such as NOx, SOx, HCl, Hg, and particulates that damage the environment and are harmful to humans. In addition to these drawbacks, corrosion and operational problems can arise from the combustion of MSW.
Fuels and waste that contain significant amounts of sulfur and/or chlorine are not desirable for combustion reactions because they can produce toxic or corrosive byproducts. Significant amounts are defined as an amount that when added to a fuel feedstock causes the final feedstock to have more than 2% sulfur and more than 1% chlorine. For example, materials such as unprocessed MSW, RDF, high-sulfur containing coal, used tires, carpet, rubber, and certain plastics such as PVC, when combusted, release unacceptable amounts of harmful sulfur and/or chlorine-based gases. For this reason, these materials are typically avoided, or have to be pretreated to remove the pollutants before being used as fuels.
Another source of fuels is from biomass. Biomass fuels are living and recently dead biological material that can be used as fuel or for industrial production. Usually biomass fuels are derived from plant matter, but they do not include coal and petroleum. Biomass fuels may also include biodegradable wastes that can be burned. Nonlimiting examples and types of biomass fuels include woods, switch grass, yard wastes, plants, including miscanthus, switch grass, hemp, corn, poplar, willow, sugarcane and oil palm (palm oil), coconut shells, and shells of nuts. Some consider the use of biomass fuels as CO2-neutral, which may be desirable for power plant operators, since the biological material stored carbon during its lifetime, and combustion simply completes the carbon cycle by returning the carbon to the environment.
Literature has extensively reported that chlorine-induced corrosion of high temperature surfaces in boilers is one of the most costly problems in the industry. This problem can result in downtime and periodic total shutdown of plants, which accounts for a significant fraction of the operating and maintenance cost. The corrosion leads to replacement of super-heater pendants as often as once a year in some units or require the use of more costly alloyed materials to either shield the metal surfaces or serve as a replacement tube material.
The corrosion problem is more severe when biomass and waste derived fuels are used due to the fact that the ash of the biomass and waste fuels has a very different composition and different melting characteristics than ash from coal. This difference in ash composition results in corrosion and chloride salt deposits on the super heater tubes and other parts of the heat transfer process units. The corrosion from chlorine begins at steam temperatures in the super-heater of approximately 480° C. (900° F.), and increases as the temperature increases up to approximately 500-600° C. (930-1,100° F.). This limits the super heated steam temperature in biomass to energy and waste to energy plants and consequently limits the power generating efficiency of biomass to energy and waste to energy plants as compared to coal-fired plants.
To prevent corrosion and control pollutants systems that have previously been developed or implemented for flue gas cleaning in combustion processes focus on the control of these pollutants in the actual fuel itself (i.e., by limiting the use fuels containing relatively high amounts of sulfur, nitrogen, heavy metals, or other pollutants and/or pollutant precursors) or by controlling the release of pollutants into the atmosphere by post-combustion treatment of the flue gas stream. For example, one pollution control strategy includes the addition of sorbents to a flue gas stream. Sorbents such as hydrated lime, calcium carbonate, sodium sesquicarbonate, sodium bicarbonate, and magnesium oxide have been injected into combustion exhaust stack gases in an effort to clean the exit gases of chlorine and sulfur containing pollutants (see, e.g., U.S. Pat. Nos. 6,303,083; 6,595,494; 4,657,738; and 5,817,283, the relevant portions of each of which are incorporated herein by reference).
However, dry sorbents optimally work at temperatures of about 800° C. to about 1,100° C. and thus have mostly been used in the exhaust stream of combustion units. Further, if sorbents such as limestone are used at temperatures below 800° C., less than 20% conversion or adsorption of the pollutants by the sorbent typically occurs, resulting in release of a substantial fraction of toxic products produced in the combustion process and/or incomplete or inefficient use of the sorbent. Accordingly, these sorbents are often prepared in slurry form and used in semi-dry/wet and wet scrubbers, which improves sorbent adsorption and/or conversion of pollutants. However, semi-dry/wet and wet scrubbers typically require more complicated process systems and operate with concomitant water consumption, leading to higher capital and operational costs.
Furnace Sorbent Injection
FIG. 1 is a schematic diagram showing an exemplary conventional coal combustion reactor comprising a furnace sorbent injection system (FSI), which is one type of sorbent system for removing pollutants from a combustion reactor exhaust stream. Pulverized or ground coal particles, typically entrained in a primary air stream, are introduced into the primary combustion zone of the combustion reactor. The primary combustion zone typically operates with an air equivalence ratio (AR) of about 0.8-1.15 (e.g., an oxygen lean to rich condition), and at a temperature of about 1,300-1,650° C. In some cases, as shown in FIG. 1, a secondary air stream may also be introduced to provide additional combustion air. The combustion products from the primary combustion zone pass into a burnout zone where the temperature is about 1,150-1,300° C. Additional air is introduced into the burnout zone to increase the AR to about 1.20 and accordingly, promote combustion of incompletely combusted fuel carried upward from the primary combustion zone. The effluent from the burnout zone then passes further up the flue of the combustion reactor to a convection zone where a sorbent is injected into the flue gas stream to adsorb SO2 produced in the combustion reaction.
Several problems may occur in conventional furnace sorbent injection systems. For example, high flue gas temperatures may promote sorbent sintering due to partial or complete melting of injected sorbent particles. For calcium-based sorbents, when the temperature greater than about 1,100° C., sintering of the sorbent particles increases drastically. Such sintering may block pores or channels in the sorbent particles, thus reducing the total effective surface area of the sorbent particles available to react with SO2, other oxides of sulfur, or other pollutants produced in the combustion reaction. High temperatures can also increase the thermal instability of desulfurization products. For example, when calcium-based sorbents are use in furnace sorbent injection processes, and the temperature is greater than about 1,050° C., CaSO4, for example, starts to decompose (e.g., CaSO4→CaO+SO2+½O2). Conversely, lower temperatures in furnace sorbent injection operations typically result in incomplete sorbent calcination, and accordingly, low sorbent reaction rates. As a result of these competing high and low temperature limitations, sorbent-injection ports in furnace sorbent injection operations must be located downstream of the coal burners in a region where the temperature is optimal for SO2 removal.
Another problem that can be encountered in typical dry and furnace sorbent injection processes is achieving sufficient residence time of sorbents to remove SO2. Sufficient residence time is necessary to allow the sorbent particles to contact the flue gases and allow for complete calcination and sulfation of the sorbent particles. However, at typical convection zone flue gas temperatures of about 700° C. to about 1,100° C., a 2 to 3 second (or longer) residence time is required for most sorbents to achieve complete calcination and sulfation of the sorbent. For typical pulverized coal boilers, residence time of injected sorbent in the convection zone is about 1 to 2 seconds, and complete calcination and sulfation of the sorbent cannot be achieved, resulting in incomplete sorbent use and less than optimal capture of SO2.
Another problem is the cost of the dry and furnace sorbent injection systems. After the sorbent is injected into the boiler or ductwork, the sorbent reacts with pollutant in the flue gas to form a solid compound that is then removed in the particulate collection devices downstream—an electrostatic precipitator or fabric filter. While this technology can eliminate the pollutants like SO3 emissions, the cost for installation and use of sorbent injection is significant and varies with the plant size and the type of reagent. Based on data from the EPA's Integrated Planning Model v4.10, the capital cost of a typical 500 MW plant can be $45,000,000 or even higher, with an annual operating and maintenance costs of over $50,000,000.
Still another problem that can be encountered in typical furnace sorbent injection processes is achieving uniform sorbent distribution across the furnace cross-sectional area when injecting sorbent. Such uniform distribution is important for achieving effective sorbent-SO2 contact and concomitant SO2 removal from the flue gas stream. However, it is difficult to practically achieve uniform sorbent distribution when injecting sorbents into a flue gas stream in FSI operations due to large furnace cross-sectional area and often complex geometric configurations of reactors. Non-uniform sorbent distribution in FSI processes may lead to incomplete mixing of injected sorbent with flue gas, resulting in lower SO2 removal efficiency and inefficient sorbent use.
Another consideration in FSI processes includes the reacting environment into which the sorbent is injected. For example, reducing or oxidizing conditions in the effluent stream may have a significant impact on SO2 removal efficiencies. In circumstances where the effluent stream is oxygen-rich (e.g., oxidizing conditions), the majority of fuel-bound sulfur is converted to SO2 with minor amounts of SO3. However, certain by-products of desulfurization, including various sulfates (SO42−), may be unstable at low temperatures relative to sulfides (SO32−). For example, CaSO4 begins to decompose at about 1,050° C. Accordingly, certain desulfurization products produced via reaction with sulfur sorbents under oxidizing conditions may be unstable and decompose, regenerating sulfur oxides. Furthermore, oxidizing conditions typically promote the conversion of fuel-bound nitrogen to NOx.
Alternatively, when combustion is conducted under reducing conditions (e.g., fuel-rich conditions), fuel-bound sulfur is converted to H2S (with trace amounts of COS), and fuel-bound nitrogen is converted to N2, with minor amounts of NH3. The by-products of desulfurization via sorbent injection into the flue gas stream under reducing conditions, such as various sulfides (e.g., CaS), are generally stable at higher temperatures relative to oxides of sulfur produced under oxidizing conditions. For example, CaS has a melting temperature of about 2,525° C. At higher temperatures under oxidizing conditions, sulfur adsorption by injected sorbent falls off dramatically, and NOx production increases. Conversely, under reducing conditions, nitrogen oxide production is very low, and sulfide production is favored. However, undesirable H2S formation is also favored under reducing conditions. Thus, flue gas sorbent injection must balance reacting conditions (e.g., oxidizing or reducing conditions) and reaction temperatures, and an optimal balance can be difficult to achieve.
Stated Flue Gas Desulfurization
Another known strategy for mitigation of SOx production in combustion processes is staged desulfurization. In this process, pulverized or ground coal particles, typically entrained in a primary air stream, are introduced into the primary combustion zone of the combustion reactor. The primary combustion zone typically operates with an air equivalence ratio (AR) of about 0.7-0.8 (e.g., a fuel rich condition), and at a temperature of about 1,500° C. A sorbent (in this case, a calcium-based sorbent at a stoichiometric ratio of Ca:S of about 1.0 to 1.5) is also introduced into the primary combustion zone, either separately from the pulverized coal, or commingled with the pulverized coal stream.
The combustion products from the primary combustion zone pass into a burnout zone where the temperature is about 1,300° C. Additional air is introduced into the burnout zone to increase the AR to about 1.20 and accordingly, promote combustion of incompletely combusted fuel carried upward from the primary combustion zone. The effluent from the burnout zone then passes further up the flue of the combustion reactor to a convection zone where a sorbent is injected into the flue gas stream at a temperature of about 1,100° C., to adsorb SO2 produced in the combustion reaction. The convection zone typically is operated at an AR of about 1.1 to 1.2, and sorbent is injected at a stoichiometric ratio of Ca:S of about 2.0 to 2.5.
However, like dry sorbent injection processes, there are several problems with staged desulfurization. For example, sorbent injected into the primary combustion zone may be sintered due to the relatively high temperature in the primary combustion zone. In addition, sorbent injected to convection zone has extremely short residence time. Further, as with dry sorbent injection, it may be difficult to achieve uniform distribution of sorbents since both sorbent and fuel particles may flow differently, or occur segregation, since they have different sizes and densities. Finally, staged desulfurization provides limited reduction of NOx produced in the combustion process.
One strategy for reducing NOx emissions is to employ a “reburn” process. In this process, pulverized or ground coal particles, typically entrained in a primary air stream, are introduced into the primary combustion zone of the combustion reactor. The primary combustion zone typically operates with an AR of about 1.05-1.10 (e.g., an oxidizing condition), and at a temperature of about 1,500° C. In some cases, a secondary air stream may also be introduced with the coal/sorbent/primary air mixture to provide additional combustion air. Fuel bound nitrogen reacts with oxygen to from NOx.
The combustion products from the primary combustion zone then pass into a reburn zone. A reburn fuel, typically natural gas, oil, propane, etc., is introduced into the reburn zone. This provides a slightly fuel rich, reducing environment (e.g., AR=0.8-0.95) wherein NOx generated in the primary combustion zone reacts with the reburn fuel induced radicals and reduces NOx to molecular nitrogen. The effluent stream from the reburn zone then passes into a burnout zone where the temperature is about 1,300° C. Additional air is introduced into the burnout zone to increase the AR to about 1.20 to promote combustion of incompletely combusted fuel and/or combustion products (e.g., CO) carried upward from the primary combustion zone. The effluent from the burnout zone then passes further up the flue of the combustion reactor to a convection zone where a sorbent is injected into the flue gas stream at a temperature of about 1,100° C. to adsorb SO2 produced in the combustion reaction.
By employing reburn technology, high levels of NOx reduction (e.g., about 50-70%) can be achieved. Further, when a reburn process is coupled with SNCR, significant levels of NOx control (e.g., greater than about 75%) can be achieved. However, reburn processes do not address the SO2 control issues described above with respect to FGD and staged desulfurization, including the balance of temperature, reaction conditions in each zone, etc. In addition, when either a combustion zone or a reburn zone are maintained at reducing conditions (e.g., AR<1), ash slagging in the combustion reactor may become significant and since ash slagging typically occurs at lower temperatures (˜100-300° F.) under reducing conditions relative to ash slagging under oxidizing conditions (e.g., AR>1).
FGD technologies like direct sorbent injection and staged desulfurization have been successful at reducing some harmful air pollutants. However, new rules and regulations have tighten the limits on pollutants released into the atmosphere, and require many power plant operators to further reduce their harmful boiler emissions. Once such rule is the U.S. Environmental Protection Agency's (EPA's) Cross State Air Pollution Rule (CSAPR), incorporated herein by reference in its entirety for all purposes, currently requires that on average power plant SO2 emissions are reduced to 73% and NOx emissions are reduced to 54% of 2005 emission levels by 2014. To comply CSAPR, the use of other FGD technologies like wet flue gas desulfurization and selective catalytic reduction (SCR) at coal-fired power plants is expected to increase significantly over the next decade. The EPA estimates that, by year 2020, the total FGD capacity is projected to increase from the current 100 gigawatts (GW) to 231 GW. The majority of this additional FGD capacity will likely use wet FGD technologies. In addition, the EPA has estimated that a total of approximately 154 GW of SCR will have been installed on U.S. coal-fired power plants by 2020.
In 2012, the EPA issued new standards for Mercury and Air Toxics Standards (MATS), incorporated herein by reference in its entirety for all purposes, which require many coal and oil power plants to substantially reduce mercury and other toxic emissions. Prior to the MATS, there had been no federal standards requiring power plants to limit their emissions of mercury and other heavy metals. In 2007, the EPA projected that the annual incremental compliance cost of MATS for power plants would be $9.4 billion in 2015. Due to these costs, the EPA expects 4.7 GW of coal-fired capacity to shutdown since they would be uneconomic under MATS. DOE testing has shown that some power plants may not be able to achieve the required reductions in mercury with dry sorbent injection systems alone for several reasons. First, SO3 interferes with mercury's ability to bind with carbon sorbents reducing the effectiveness of some dry sorbent injection systems. Second, the use of hot-side electrostatic precipitators (ESPs) has the unintentional side effect of reducing the amount of mercury that can bind to sorbents and be collected as particulate matter. Third, it is difficult for dry sorbent injection systems to thoroughly treat flue gas from boilers combusting coal that is high in elemental mercury, and without installing an additional baghouse, it would be impossible to achieve over 90% mercury reduction required by MATS, especially for sub-bituminous or high sulfur coals.
Meeting these new emission standards has unintentional side effects. While an increase in the use of wet FGD and SCR controls will significantly reduce SO2 and NOx emissions, it will unfortunately make stack opacity a more prevalent problem. As described in greater detail below, the reason for the increase in stack opacity is a result of the increase in SO3 due to the further oxidation of SO2. This phenomenon that has already been experienced in coal-fired plants retrofitted with SCR and/or wet FGD controls, and is particularly problematic in plants that burn high sulfur containing bituminous coals.
Condensed SO3 or its hydrated acidic form, sulfuric acid (H2SO4), is one of the major contributors to stack opacity problems—a phenomenon commonly known as “blue plume.” Estimates are that 75% to 85% of bituminous coal-fired plants with SCR and/or wet FGD systems are likely to produce enough SO3 vapor and aerosol mist to make their emissions opaque. For example, in 2000 following the installation of SCR units at American Electric Power's 2,600-MW General Gavin Plant in Ohio, a notable instance of blue plume occurred because the plant's SO3 emissions doubled because of the SCR. This increase is attributed to the further oxidization of SO2 by the catalysts packed in the SCR unit. The SCRs use oxidative catalysts, for example titanium dioxide, vanadium pentoxide, and other titanium-vanadium catalysts, that promotes convertion of SO2 to SO3.
The visible consequences of sulfuric acid aerosol emissions are not the only problem associated with SO3 in flue gas. It also results in several adverse health, environmental, and aesthetic consequences and produces significant operational and maintenance disadvantages for operators of coal-fired power plants. In sufficient concentration, SO3 can increase corrosion and fouling of equipment and components downstream of the furnace or boiler, including but not limited too, the ductwork, air heater, ESP, or fabric filter (FF), and the smoke stack itself. Further, the increased SO3 can also decrease the efficiency and diminish the overall plant heat rate. With higher SO3 levels in flue gas exiting furnace or boiler and/or SCR, the air heater is forced to be operated at a gas outlet temperature far above the acid dew point temperature, which means the heat recovery by the air heater will be lower, consequently lowering the plant's thermal efficiency. At the same time, the resultant higher flue gas volumetric flow due to higher flue gas temperature will lower ESP/FF particulate removal efficiency, further contributing to stack opacity issues. The higher flue gas volumetric flow will also lead to more electric power consumption by induced draft (ID) fans. Also the SCR catalytic surfaces can be blinded by excess arsenic and mercury that will also be present with excess SO3.
Raising the air heater operation temperature at least 20-30° F. above the acid dew point can avoid SO3 condensation, but the consequence is that it will reduce the plant efficiency. Alternatively, reheating the flue gas before it is discharged to the stack can also reduce the blue plume risk, but significant consumption of energy is required to do so. Moreover, these strategies only solve the blue plume caused visibility issue, they do not help reduce SO3 emissions to the atmosphere and associated air pollution issues.
Though the specific SO3 concentration at which visible effects are seen varies with atmospheric conditions and stack characteristics, it is generally accepted that if the SO3 concentration is less than about 5 to about 10 ppm, there will be no visual discoloration effects. Experience from the power industry also indicates that reducing the SO3 concentration in the flue gas to low levels (<10 ppm) prior to the air heater will reduce the likelihood of downstream component corrosion and fouling. Reducing the SO3 concentrations at furnace or boiler outlet from a typical 30 ppm to about 5 ppm would allow the air heater to operate at least 35° F. lower in gas outlet temperature. This would result in an about 1% increase in heat rate (or plant efficiency), which would be worth about $2,233,800 (for a 500 MW plant with 85% operation factor and power rate at $60/MWh).
Therefore, there is a need for innovative, efficient and cost-effective methods to mitigate harmful air pollutants and related environmental, economical and operational issues associated with coal-fired power plants.
There is also a need for new systems and methods for reducing pollutants, particularly SOx, NOx, HCl, and Hg produced in combustion processes in an integrated fashion to provide maximum pollutant removal and avoid at least some of the problems associated with conventional SOx, NOx, HCl, and Hg reduction technologies.